Coalbed Methane Reservoirs Research Articles

Influencing Mechanism of Temperature on Coal Pores during the Artificially Thermal Evolution

The pores in coal are the primary storage sites of coalbed methane (CBM), and temperature is the critical factor affecting pore evolution during the thermal evolution. This paper investigates the evolution characteristics of different pores and the role of related molecular structures through the artificially thermal evolution of coal. The pore size distribution and morphology of unheated and heated coals were detected by combining the fluid injection technology and image analysis. The molecular structures of each sample are semi-quantitatively analyzed by X-ray diffraction and Fourier transform infrared spectroscopy. The results indicated that 300 °C is a turning point for the evolutions of micropores and macropores. Their respective volume remains steady approximately before 300 °C. Subsequently, the micropore volume increases gradually, while the macropore volume soars suddenly after 300 °C. Meanwhile, the mesopore volume constantly decreases during the artificially thermal evolution. On the other hand, the most mesopore morphology alters from the slit pore and wedge pore to the bottle-neck pore and cylindrical pore, while the macropore morphology alters from the wedge pore into the cylindrical pore and bottle-neck pore. Furthermore, during the artificially thermal evolution, the major factor affecting the evolution of micropore and macropore is the loss of −CH2 side chains from their edges, while the main factor affecting the mesopore evolution is the polycondensation of −CH2 side chains and carbonyl/carboxyl at its edge. These results could help understand the pore variation in CBM reservoirs during coalification.

In situ stress variation and coal reservoir permeability response of the Jurassic Yan'an formation in the southwestern Ordos basin, China: Its impact on coalbed methane development

The in situ stress (ISS) and permeability determine the coalbed methane (CBM) development method and extraction efficiency to a certain extent. Based on the data of the CBM well test and microseismic monitoring in the Jurassic Yan'an Formation, a prediction model of the ISS is established, and its influence on permeability and CBM development in the southwestern Ordos Basin, China, is discussed. The results show that the orientations of maximum principal stresses (Shmax) in the study area's eastern, central, and western parts are NE–SW, SEE–NWW, and NNW–SSE, respectively. With the increased burial depth, the main ISS parameters show an S-shaped variation. The study area's ISS state can be divided into Shmax > vertical stress (Sv) > horizontal minimum principal stress (Shmin) (<420 m), Sv > Shmax > Shmin (420 m–800 m), and Shmax ≈ Sv > Shmin (>800 m), and the transformation depth of the ISS field is 550 m and 1000 m. The lateral pressure coefficients (λ) ranged from 0.30 to 1.19, with an average of 0.69. The λ, Shmax/Shmin and Shmin/Sυ of the stress field are small, which indicates that the horizontal tectonic stress is weak. The coal reservoir's permeability is distributed between 0.0084 and 6.84 mD (av. 1.13 mD). Affected by the variation of the ISS state in the vertical direction, the coal reservoir permeability shows obvious zoning. The tensile stress field is beneficial to high-permeability coal reservoir formation, but it is constrained by the coupling constraints of a coal reservoir's confining pressure and effective stress. The coal reservoirs are in a normal fault stress state, which is beneficial for improving their hydraulic fracturing effect. Since the Shmin in the study area is always smaller than the Sυ, the height of the fracturing fracture should be controlled in the fracturing of the coal reservoir to avoid the overlying aquifer being connected by fracturing fractures. The above new insights have important guiding significance for the hyperpermeability CBM reservoir prediction, well-bore structure and hydraulic fracturing design in the Ordos Basin.

Modelling multicomponent gas diffusion and predicting the concentration-dependent effective diffusion coefficient of coal with application to carbon geo-sequestration

Diffusion of multicomponent gases, which is a complex transport mechanism in coalbed methane (CBM) reservoirs, needs to be accounted for in models of enhanced coalbed methane recovery (ECBM) and geological CO2 storage. We develop a numerical model that accounts for diffusion of free gas, diffusion of adsorbed gas, and competitive sorption. Our model also reflects adsorption-induced swelling and the impact of moisture. The simulator for modelling multicomponent gas diffusion is first validated by comparing its computed concentration field against those yielded by the general-purpose finite element solver COMSOL and the available analytical solutions. The model is then validated against the experimental measurements from the published literature. Subsequently, our simulator is used to model the CO2 Enhanced Coalbed Methane (CO2-ECBM) scenarios. The simulation results quantify the influence of different types of diffusion on the effective diffusion coefficient of coal. We analyse diffusion of methane and carbon dioxide that must be considered when modelling CBM reservoirs and analyse performance-based sensitivity of surface diffusion, moisture, matrix deformation, and pressure. Finally, the model is applied to a CO2 storage case. We calculate the CO2 storage volume and the equilibrium time under various pore pressures. The simulation shows that as pore pressure increases, the amount of CO2 stored increases and the equilibrium time decreases. Overall, this model can be applied to estimate the effective diffusion coefficient, to analyse the impact of rock and gas parameters on multicomponent gas diffusion, to provide insight into the physics of multiple gas transport in coal, and to estimate the feasibility of CO2 storage under various pore pressures.

Characteristics of water occurrence in coalbed methane reservoir

Characteristics of water occurrence in coalbed methane reservoir

Summary of research methods for porosity and permeability of coalbed methane reservoir

In order to serve the research on the physical properties of coalbed methane reservoirs and improve the prediction effect of porosity and permeability of coal reservoirs, this paper, based on a large number of literature research, summarizes the concepts, influencing factors and prediction methods of coal seam porosity and permeability. The research shows that the main factors affecting the porosity of coalbed methane reservoir are coal petrographic composition, metamorphic degree, coal body structure and buried depth, compaction, tectonism, etc; The main influencing factors of permeability include component content, coal rank, coal body structure and in-situ stress, buried depth of coal seam, natural fracture of coal seam, matrix shrinkage, Klinkenberg effect, etc. The porosity prediction of coalbed methane reservoir generally adopts true and apparent relative density method, in addition, there are multiple regression method based on logging information, nuclear magnetic resonance logging method, etc; The measurement methods of CBM reservoir permeability mainly include the calculation method based on conventional logging, triaxial stress experimental research method, joint prediction method of nuclear magnetic resonance and electrical imaging logging, dynamic data analysis method and numerical simulation method. The development of coal seam porosity and permeability prediction technology needs innovative breakthroughs in hardware and software.

Coalbed Methane Reservoir Parameter Prediction and Sweet-Spot Comprehensive Evaluation Based on 3D Seismic Exploration: A Case Study in Western Guizhou Province, China

As a kind of clean energy, the exploration and development of coalbed methane (CBM) are of great importance and significance. In this paper, the CBM reservoir parameters of a working area in Western Guizhou Province, China, were predicted by using 3D seismic exploration technology, and the sweet-spot area was evaluated based on the prediction results. In terms of data interpretation, while the traditional technology is extended to the study of CBM, new technologies and methods suitable for CBM were also actively explored, especially in the quantitative prediction methods of parameters such as coal seam thickness, CBM content, coal body structure, in situ stress, etc., and a three-highs quantitative prediction technology of CBM sweet spots characterized by high precision, high resolution, and high coincidence was explored, which is based on logging evaluation and petrophysics. In addition, in the comprehensive evaluation of multiparameter sweet spots, the multiparameter weighted step-by-step evaluation method based on inversion was innovatively proposed, which made the prediction of CBM sweet spots more focused, effective, and practical, and the distribution law of sweet spots was more consistent with the geological law, providing enough basis for subsequent well location deployment. Based on this method, the C409 coal seam was selected as the sweet spot.

Numerical investigation of seepage characteristics of propped fracture in coalbed methane reservoirs

The investigation of the pore structure characteristics and the effect on fluid seepage in propped fractures are important considerations for improving coalbed methane (CBM) production and optimizing CBM extraction systems. In this paper, a numerical model was established to study the pore structure characteristics and distribution of fluid pressure, velocity and pathline fields of propped fractures. The results showed that, with the increase of the closure stress, the porosity decreased linearly while the effective pore connectivity ratio first increased, then decreased. The best flow conductivity of the fracture was achieved at the closure stress of 12.67 MPa. In addition, there were disparities in the pore distribution of the different layers due to the uneven transfer of the closure stress from top to bottom. Compared to the top and bottom layers, the effective pore connectivity ratio and fluid pressure were significantly smaller in the middle layer, while the flow velocity and pathline length were larger. The top and bottom layers were the main fluid seepage channels. The results of this study can provide a theoretical basis for CBM production prediction and real-time quantitative optimization of CBM extraction systems.

Conductivity Evaluation of Horizontal Wells in Coalbed Methane Reservoirs: Applicability of Micromaterial Tracer Testing Technology.

Horizontal well-staged fracturing technology is widely used in the exploitation of coalbed methane reservoirs. Most coalbed methane wells have little or no flowback fluid after fracturing due to strong adsorption in the reservoir. The fracture conductivity of each fracturing interval can only be evaluated in the water drainage and gas production stage. Traditional chemical tracer monitoring technologies are risky to operate and do not provide accurate qualitative measurements. The potential applicability of trace material tracer testing technology in coalbed methane reservoirs has theoretical and practical significance, as does establishing a set of fracturing tracer technologies (e.g., reagent systems, construction schemes, detection interpretation) suitable for coalbed methane horizontal wells. Geological, laboratory, and field test data are used in this study to preliminarily resolve the trace material tracer adsorption problem in the coalbed by improving the chemical agent formula. The proposed method is applied to determine the conductivity of a fractured section in a coalbed methane well.

Advances in Cryogenic Fracturing of Coalbed Methane Reservoirs with LN2

Coalbed methane (CBM) is a significant unconventional natural gas resource existing in matrix pores and fractures of coal seams and is a cleaner energy resource compared to coal and crude oil. To produce CBM, stimulation operations are required, given that the coal permeability is generally too low. Hydraulic fracturing is the most widely used technology for reservoir stimulation; however, there are a few challenging issues associated with it, e.g., huge water consumption. In the past decade, the use of liquid nitrogen (LN2) as a fracturing fluid has been intensively studied for stimulating CBM reservoirs, achieving considerable progress in understanding fracturing mechanisms and optimizing fracturing techniques. This paper presents a thorough review of experimental design and observations, modeling procedures and results, field applications, and published patents. Existing studies are divided into five different groups for discussion and comparison, including immersion tests, injection tests, jet drilling tests, numerical modeling, and field applications. Based on the comprehensive evaluation of the outcomes, it is obvious that cryogenic fracturing using LN2 is a promising eco-friendly fracturing technique that can effectively enhance coal rock permeability to increase the production of CBM.

Study on H-shaped fracture propagation and optimization in shallow dull-type coal seams in the Hancheng block, China

The initiation and propagation of hydraulic fractures dominate the fracture morphology and conductivity, thereby determining the fracturing stimulation effect. This work took the shallow dull-type coal seam in the Hancheng block as the research object, and focused on the propagation and optimization of the H-shaped fracture. By using a combination of mechanical theoretical analysis, laboratory experiment, numerical simulation, field test, and optimization evaluation, an integrated study on the formation conditions, morphology evolution, propagation laws, main controlling factors, and optimal design of H-shaped fractures was conducted. The mechanical criterion for identifying H-shaped fracture propagation was derived through the analysis of the stress fields on the fracture surface. A 3D numerical model of H-shaped fractures was established with cohesive element method, and the propagation law and influencing factors of H-shaped fractures were investigated. Sensitivity analysis of the influencing factors on the H-shaped fractures was performed with grey incidence analysis method. The optimization of the H-shaped fracture parameters was performed by fracture propagation numerical simulation. The results show that H-shaped fractures dominated by horizontal fractures are generally formed in shallow dull-type coal seams. H-shaped fractures can improve the CBM development effect by parameter optimization of indirect fracturing technology. The judging criterion for H-shaped fracture formation is that the tensile strength of the upper and lower weakly cemented horizontal interfaces is less than that of the coal seam and the vertical principal stress is lower than the minimal horizontal principal stress. The incidence degree of fracturing fluid injection rate, viscosity, perforation location, minimum horizontal stress difference, and coal seam permeability on the H-shaped fracture propagation decreases in turn. The engineering factors (fracturing fluid injection rate and viscosity and perforation location) are the major impact factors. With the increase in coal seam permeability, the horizontal fracture develops from stubby-type to slender-type. The minimum horizontal principal stress difference mainly affects the horizontal fracture. As the fracturing fluid viscosity increases, the horizontal fracture length increases first and then decreases. The fracturing fluid injection rate has a great impact on the height-length profile of horizontal fractures. The optimal injection rate seems to be 6.5–7 m3/min, the optimal fracturing fluid viscosity is between 10 mPa·s and 15 mPa·s, and the optimal perforation location is selected near the formation interface. These research results could provide a reference for the design and optimization of efficient fracturing of coalbed methane reservoirs.

Upscaling poromechanical models of coalbed methane reservoir incorporating the interplay between non-linear cleat deformation and solvation forces

We construct herein a three-scale coupled mechanical model for naturally fractured coalbed methane reservoir with the ability of describing the stress balance between the solvation force, arising from the gas adsorption in nanopores, and the restoration stress stemming from the elastic response of the cleats. To determine the cleat porosity, the non-linear hyperbolic Barton–Bandis (BB) law, which captures increase in joint stiffness induced by the cleat closure due to matrix swelling, is postulated for the fracture mechanical response. At the microscale, the theory incorporates the coupling between the effects of the solvation force and the elastic response of the matrix. Such system of governing equations is coupled with the fluid pressure in the discrete cleat system with dependency of aperture with the normal stress dictated by the aforementioned BB-model. A reiterated homogenized procedure is pursued and capable of providing the constitutive response of the homogenized poromechanical parameters on gas pressure. Numerical simulations illustrate the performance of the proposed model.

Experimental study of relationship among acoustic wave, resistivity and fluid saturation in coalbed methane reservoir

Experimental study of relationship among acoustic wave, resistivity and fluid saturation in coalbed methane reservoir

Thermal recovery of offshore coalbed methane reservoirs: Flow characteristics of superheated steam in wellbores

Methane in coalbed methane (CBM) reservoirs is mainly in the adsorbed state, and has both free and dissolved states. The proportion of adsorbed methane can be as high as 90% or more. Field practice shows that low methane desorption efficiency is one of the keys affecting CBM development. The adsorption of methane is significantly affected by temperature, and the desorption efficiency increases with the increase of temperature. In this paper, the wellbore flow during the development of CBM reservoirs by injection of superheated steam is taken as the research object, and the superheated steam flow model is established considering the influence of seawater disturbance caused by the phase change of superheated steam. The study found: (a) In the formation section wellbore, the superheated steam has the highest temperature value. (b) The temperature of the superheated steam is affected by both the Joule Thompson effect and the heat loss effect. (c) The longer the wellbore in the seawater section, the lower the temperature of the superheated steam in the wellbore. (d) Superheated steam is only suitable for shallow sea conditions.

The generalized method for estimating reserves of shale gas and coalbed methane reservoirs based on material balance equation

As the main unconventional natural gas reservoirs, shale gas reservoirs and coalbed methane (CBM) reservoirs belong to adsorptive gas reservoirs, i.e., gas reservoirs containing adsorbed gas. Shale gas and CBM reservoirs usually have the characteristics of rich adsorbed gas and obvious dynamic changes of porosity and permeability. A generalized material balance equation and the corresponding reserve evaluation method considering all the mechanisms for both shale gas reservoirs and CBM reservoirs are necessary. In this work, a generalized material balance equation (GMBE) considering the effects of critical desorption pressure, stress sensitivity, matrix shrinkage, water production, water influx, and solubility of natural gas in water is established. Then, by converting the GMBE to a linear relationship between two parameter groups related with known formation/fluid properties and dynamic performance data, the straight-line reserve evaluation method is proposed. By using the slope and the y -intercept of this straight line, the original adsorbed gas in place (OAGIP), original free gas in place (OFGIP), original dissolved gas in place (ODGIP), and the original gas in place (OGIP) can be quickly calculated. Third, two validation cases for shale gas reservoir and CBM reservoir are conducted using commercial reservoir simulator and the coalbed methane dynamic performance analysis software, respectively. Finally, two field studies in the Fuling shale gas field and the Baode CBM field are presented. Results show that the GMBE and the corresponding straight-line reserve evaluation method are rational, accurate, and effective for both shale gas reservoirs and CBM reservoirs. More detailed information about reserves of shale gas and CBM reservoirs can be clarified, and only the straight-line fitting approach is used to determine all kinds of reserves without iteration, proving that the proposed method has great advantages compared with other current methods.

Technical advances in well type and drilling & completion for high-efficient development of coalbed methane in China

Compared with the United States, Australia, Canada, and other countries, China's coalbed methane reservoir is featured by low formation pressure, low permeability, low gas saturation, and strong heterogeneity, which not only increases the difficulty of reservoir stimulation but also restricts the single well production and the recovery efficiency of coalbed methane (CBM). In view of this, the research and application of horizontal drilling and completion technology of CBM at home and abroad are reviewed to provide references and theoretical supports for the advancement of the horizontal well engineering technology of CBM in China. This paper introduces a series of horizontal drilling and completion technologies (e.g., the well type design, well structure optimization, well trajectory control, wellbore stability, completion optimization, reservoir protection, etc.). The advanced technologies and their adaptability, including screen pipe completion and stimulation with dual-layer tubular strings, radial horizontal well screen pipe completion and magnetic steering drilling, are dialectically discussed in this paper. In addition, a novel integrated engineering mode for the efficient and green development of deep CBM and coal through the underground “well factory” is proposed. The conclusions are as follows: (1) In view of the geological conditions and surface environment of the coal seam in China, the horizontal drilling and completion technologies of high rank coalbed methane should be further refined, and an integrated development for the coal measure gas is required; (2) More efforts should be made to strengthen the innovative research on horizontal drilling & completion technology for low-medium rank coals and the broken coal, so as to identify the efficient development mode for the complex coalbed methane reservoir; (3) When encountering major technical challenges during the green and efficient development of unconventional coal mines such as deep coal mines, low grade coal mines and thin coal seams in China, it is necessary to explore the development mode via in-situ conversion process based on underground “well factory” to realize the integrated green and efficient development of deep CBM and coal; (4) The high quality transformation with low-carbon and green energy in China will not only ensure national energy security, but also achieve the goal of “carbon peaking and carbon neutrality”.

Productivity enhancement in multilayered coalbed methane reservoirs by radial borehole fracturing

Coalbed methane (CBM) is an important unconventional natural gas. Exploitation of multilayered CBM reservoir is still facing the challenge of low production rate. Radial borehole fracturing, which integrates radial jet drilling and hydraulic fracturing, is expected to create complex fracture networks in multilayers and enhance CBM recovery. The main purpose of this paper is to investigate the mechanisms and efficacy of radial borehole fracturing in increasing CBM production in multiple layers. First, a two-phase flow and multi-scale 3D fracture network including radial laterals, hydraulic fractures and face/butt cleats model is established, and embedded discrete fracture model (EDFM) is applied to handle the complex fracture networks. Then, effects of natural-fracture nonuniform distribution are investigated to show the advantages of targeted stimulation for radial borehole fracturing. Finally, two field CBM wells located in eastern Yunnan-western Guizhou, China were presented to illuminate the stimulation efficiency by radial borehole fracturing. The results indicated that compared with vertical well fracturing, radial borehole fracturing can achieve higher gas/water daily production rate and cumulative gas/water production, approximately 2 times higher. Targeted communications to cleats and sweet spots and flexibility in designing radial borehole parameters in different layers so as to increase fracture-network complexity and connectivity are the major reasons for production enhancement of radial borehole fracturing. Furthermore, the integration of geology-engineering is vital for the decision of radial borehole fracturing designing scheme. The key findings of this paper could provide useful insights towards understanding the capability of radial borehole fracturing in developing CBM and coal-measure gas in multiple-thin layers.

Moisture Retention and Multi-mechanistic Transport Behavior in Nanoporous Coal.

Coal-water interactions induced by water retention in coals control the performance of coalbed methane reservoirs and coal utilizations. Experimental measurements on Illinois coal samples using X-ray diffraction, X-ray photoelectron spectroscopy, Fourier transform infrared spectroscopy, low-temperature N2 adsorption, low-pressure CO2 adsorption, and dynamic water vapor sorption were carried out. A mechanism-based isothermal model of water vapor sorption was proposed to estimate the water adsorption capacity at varied relative humidity, which implicitly considered both monolayer and multilayer adsorptions and capillary condensation. The analytical models for quantifying the stage-based diffusion coefficients as well as the apparent diffusion coefficients at different relative humidities were proposed and well validated. The contributions of different diffusion regimes to the total mass flow were discussed. At the first stage, both free water vapor diffusion and surface diffusion of adsorbed water molecules contribute to the total mass flow whereas the apparent diffusion at this stage is dominated by latter flow regime; during the second stage, the contribution of free water vapor flow to the apparent flow can be neglected and the mass transfer at this stage is still dominated by the surface diffusion flow; upon reaching the critical relative humidity, the flow in capillary condensation will dominate the total mass flow.

A systematic data-driven approach for production forecasting of coalbed methane incorporating deep learning and ensemble learning adapted to complex production patterns

Coalbed methane(CBM) as an essential component of clean energy is of strategic significance to global sustainable development, with its production forecast being the basis for reservoirs development. However, due to complex mass transfer mechanism under different geological conditions, traditional physics-based methods are difficult to cope with the complex and various CBM production behavior. Considering the actual production characteristics, this study innovatively combines supervised learning and unsupervised learning to develop an autonomous data governance system based on Local Outlier Factor(LOF) and eXtreme Gradient Boosting(Xgboost), which can perform anomaly detection of dynamic CBM data as well as missing value supplement. Additionally, a data-driven production forecasting model is designed incorporating a Bi-directional Long-Short-Term-Memory(Bi-LSTM) to tackle the various production curve patterns of CBM wells. The production curves from 782 wells of real CBM reservoirs were classified into I, II, III, and IV patterns in terms of their characteristics, with percentages of 32%, 29%, 20%, and 19% respectively. The results reveal that the LOF-Xgboost governance system not only enhances the short-term prediction performance but also significantly improves the long-term prediction robustness. The improved Bi-LSTM-based production model of CBM shows more powerful adaptability and accuracy for both conventional curve patterns and irregular production behavior.

Experimental comparisons of different cryogenic fracturing methods on coals

Hydraulic fracturing using water-based fracturing fluids is widely used in coalbed methane (CBM) reservoir development. However, the stimulation efficiency of conventional hydraulic fracturing in CBM reservoir is low. Liquid nitrogen (LN2) cryogenic fracturing is one possible method to improve the stimulation efficiency. To test the feasibility of the LN2 cryogenic fracturing, laboratory fracturing tests were conducted to investigate the performances of different LN2 cryogenic fracturing methods in this paper. The breakdown pressure and fracture morphology of water fracturing, LN2 direct fracturing, LN2 freeze fracturing, LN2 freeze-thaw fracturing and LN2 compound fracturing were compared. And the mechanisms of different cryogenic fracturing techniques are revealed. The results demonstrate that thermal damage caused by LN2 freezing is the main reason for the complicated fracture pattern in cryogenic fracturing. LN2 freeze-thaw fracturing has the lowest breakdown pressure and can create the most complex fractures among these cryogenic fracturing methods due to the huge thermal damage. LN2 freeze fracturing has the highest breakdown pressure. Because the thermal damage cracks and natural fractures in frozen rock are in freezing shrinkage, which activation are difficult. LN2 compound fracturing is the most potential technologies, which can produce more complex fracture networks than water fracturing and LN2 fracturing.

Thermal recovery of coalbed methane: Modeling of heat and mass transfer in wellbores

Coalbed methane (CBM) reservoirs have the characteristics of low porosity, low permeability, strong heterogeneity and high content of adsorbed gas. A large number of studies have shown that the adsorption performance of coalbed methane reservoirs on methane is significantly affected by temperature. Therefore, heat injection development of coalbed methane reservoirs has received extensive attention. This paper takes the superheated steam (SS) flow in the wellbore after fracturing the coalbed methane reservoir as the research object, and establishes a mathematical model of the SS flow. The model consists of momentum conservation equation and energy conservation equation as the main control equation, combined with auxiliary models to form a complete mathematical model. In this paper, the discrete method is used to obtain the numerical solution of the model, and then the influence of the injection parameters on the SS flow is analyzed. The research conclusions of this paper have reference significance for the development of coalbed methane reservoirs with SS injection. This study found that: (a) When the injection rate is low enough (0.2 kg/s in this paper), the effect of gravity on SS pressure is stronger than that of pressurized gas; (b) When the steam injection speed is within a certain range (0.5 kg/s in this example), the pressure of the SS first decreases and then increases, forming a U shape; (c) The SS temperature increases with increasing of injection rate. During this period, the Joule-Thompson effect replaces the heat loss effect as the main factor controlling the temperature drop of the SS; (d) In order to maintain the development advantages of SS, the SS should still have a certain degree of superheat at the bottom of the well. Therefore, the steam injection speed should not be too high (eg 0.2 kg/s in this article); (e) Therefore, with the increase of SS pressure inside the wellbore, the temperature value decreases due to the influence of Joule Thompson effect, resulting in the continuous decrease of superheat degree.